One of the major objectives of open hole logging in hydrocarbon exploration wells is to evaluate the fluid flow properties of the reservoir. Flow properties of particular interest include the relative fluid saturation at a given capillary pressure, the fluid flow permeability, the fluid viscosities, and the volume of bound formation water. The capillary bound water saturation determines the volume fraction of water in the pore space that will flow from the rock. This volume fraction subtracted from the total rock pore volume provides a measure of the maximum producible oil volume. The fluid flow permeability indicates how fast the fluid will flow through the rock for a given pressure gradient. These fluid flow properties are required to determine the economics of the reserve and for field development planning, such as the number of wells, well spacing, surface facilities, pipeline facilities, etc, which will be needed for production.
At present three methods are used for determining the reservoir rock fluid flow parameters: (1) formation micro-test and well testing; (2) coring and core analysis, and (3) inference from well logging measurements. Formation micro-testing and well testing involve the actual production of reservoir fluids from a specific reservoir interval. The disadvantage of this method is its high cost and that the flow parameters are only obtained over small reservoir intervals. The second option is to cut cores and determine the flow properties by laboratory core analysis measurements. This procedure is costly and reservoir flow parameters are only determined for selected reservoir intervals where cores from which cores are cut. There is also an additional uncertainty introduced on the measured flow parameters because of the possibility that the fluids redistribute in the pore space when the core is removed from the reservoir. The third option is to infer fluid flow parameters from logging measurements. This has the advantage of providing continuous data over the large reservoir intervals at much lower cost. The major disadvantage is that the fluid flow properties of the reservoir are inferred from measurements on non-flowing fluids, rather than measured directly on fluid flowing in the rock.
The fluid flow permeability, κ, is defined by Darcy's law:υ=−(κ/η)∇P  (1)where υ is the flow velocity, ∇P is the pressure gradient and κ/η, the ratio of permeability to viscosity, is the fluid mobility. At present the only direct measurement of permeability is obtained by laboratory core analysis. In these laboratory measurements the viscosity of the fluid and pressure gradient are known and the velocity is measured. The permeability is then readily derived from data fitting using the Darcy law definition of permeability. By contrast, permeabilities derived from well testing and repeat formation testers are not measured directly but rather are derived from modeling the data from these measurements. In general, the experimental control parameters such as fluid velocity, viscosity, and pressure gradient are not known and must be included in the fit parameters of the model. The model must also include other parameters such as the pressure gradients in the reservoir and the radial flow profiles that control bulk flow into the borehole. This large number of fit parameters has the consequence of introducing large uncertainties in the estimation of the permeability.
Wire line logging tools have the advantage that data can be quickly and comparatively inexpensively obtained over very large reservoir intervals. This is especially important early in the appraisal stage of exploration wells where logging data is used to identify reservoir intervals where the more expensive well tests or formation micro-tests measurements will be made. The major disadvantage of all continuous log wire line tools is that the fluid permeability is not directly measured but is inferred from other petrophysical properties of the reservoir rock. Permeabilities are derived using empirical correlations established from laboratory measurements of permeability on cores and the characteristic tool response parameters. The primary tools used for this type of analysis are the sonic, electrical conductivity, and nuclear magnetic resonance (NMR) logging tools. For the sonic measurements, the permeability is derived from the attenuation of the elastic wave propagating along the borehole or in the formation. A major complication is that the attenuation is determined by the bulk properties, which includes both the grain and fluid properties. For the conductivity measurements, the permeability is derived using the Kozeny-Carmen relationship. A major complication in this measurement is that the conductivity varies with salinity as well as the relative saturation of hydrocarbons and also depends on the amount and types of clays and minerals present. For the NMR measurements, the permeability is inferred from an assumed simple relation between the NMR relaxation time distribution and the pore size distribution. However this relationship is complex and the NMR relaxation time spectrum can only be converted to a pore size distribution in ideal circumstances when all relevant parameters such as the surface relaxivity and contributions of the pore-to-pore coupling are known. As a result of the complications in the interpretation of each of these measurements, the permeability inferred from the data analysis is bounded by large uncertainties.
The present invention describes a method to determine fluid flow velocities in the reservoir rock in the presence of a known pressure gradient. The analysis of the data to determine permeability does not require assumptions about bulk flow into the borehole such as required for the analysis of well test and formation micro-test data. The measurement is also made using a wire line tool under continuous logging conditions so that data over large reservoir intervals are obtained.